System and method for downhole blowout prevention

ABSTRACT

A system for monitoring and controlling fluid flow through a borehole in an earth formation is disclosed. The system includes: a downhole tool configured to be movable within the borehole; and a plurality of interchangeable modules disposed within the downhole tool, the plurality of interchangeable modules including at least a sensor module for detecting a property change in the borehole and a packer module for sealing a portion of the borehole in response to the property change. Each of the plurality of interchangeable modules includes a connection configuration, the connection configuration of one of the modules being removably engageable with at least another of the modules. A method of monitoring and controlling fluid flow through a borehole in an earth formation is also disclosed.

BACKGROUND OF THE INVENTION

Blowout prevention is a significant concern in hydrocarbon exploration and production. Blowouts generally refer to uncontrolled fluid or gas flow from an earth formation into a wellbore, which could potentially flow to the surface. Despite health, safety and environment (HSE) issues, this causes loss of income either directly or by reduced or delayed production. Blowout preventers are provided to seal all or a portion of the wellbore in response to a kick, i.e., a sudden flow of formation fluid, such as water, oil and/or gas, into the borehole. Such action prevents the kick from evolving into a blowout at the surface. Kicks usually refer to influxes when drilling into an over pressured zone but include also influxes occurring when the well pressure becomes lower than the pore pressure, which is a consequence of loss of circulation fluid occurring when the well pressure is partially higher than the fracture pressure or when drilling into permeable low-pressure formations.

Various independent pressure barriers are used during drilling operations. Such barriers include the use of heavy mud, surface blowout preventers (BOP) and downhole BOPs. Typical blowout prevention devices, and especially downhole BOPs, do not allow for ease of replacement of various components or addition or subtraction of supplemental capabilities.

BRIEF DESCRIPTION OF THE INVENTION

A system for monitoring and controlling fluid flow through a borehole in an earth formation includes: a downhole tool configured to be movable within the borehole; and a plurality of interchangeable modules disposed within the downhole tool, the plurality of interchangeable modules including at least a sensor module for detecting a property change in the borehole and a packer module for sealing a portion of the borehole in response to the property change. Each of the plurality of interchangeable modules includes a connection configuration, the connection configuration of one of the modules being removably engageable with at least another of the modules.

A method of monitoring and controlling fluid flow through a borehole in an earth formation includes: disposing a plurality of interchangeable modules within a downhole tool, the plurality of interchangeable modules including at least a sensor module and a packer module, each of the plurality of interchangeable modules including a connection configuration, the connection configuration of one of the modules being removably engageable with at least another of the modules; detecting a change in property in the borehole by the sensor module; and responsive to the change in property being greater than a selected threshold, actuating the packer sub to seal a portion of the borehole.

BRIEF DESCRIPTION OF THE DRAWINGS

The following descriptions should not be considered limiting in any way. With reference to the accompanying drawings, like elements are numbered alike:

FIG. 1 depicts an embodiment of a drilling and/or well logging system including a downhole blowout prevention (BOP) tool;

FIG. 2 depicts an exploded side view of an embodiment of a downhole BOP tool;

FIG. 3 depicts a side view of a bypass sub of FIG. 2;

FIG. 4 depicts a side view of a packer sub of FIG. 2 in a non-actuated position;

FIG. 5 depicts a side view of the packer sub of FIG. 2 in an actuated position;

FIG. 6 depicts a side view of an exemplary embodiment of the downhole tool of FIG. 2;

FIG. 7 depicts a side view of another exemplary embodiment of the downhole tool of FIG. 2;

FIG. 8 depicts a side view of another exemplary embodiment of the downhole tool of FIG. 2;

FIG. 9 is a block diagram of a system for preventing blowouts in a borehole; and

FIG. 10 is a flow chart providing an exemplary method preventing blowouts in a borehole.

DETAILED DESCRIPTION OF THE INVENTION

Referring to FIG. 1, an exemplary embodiment of a drilling and/or well logging system 10 includes a drillstring 11 that is shown disposed in a borehole 12 that penetrates at least one earth formation 14. The drillstring 11 includes a drill pipe, which may be one or more pipe sections or coiled tubing. Drilling fluid, or drilling mud 16 may be pumped through the drillstring 11 and/or the borehole 12. In one embodiment, a bottom hole assembly (BHA) 18 is disposed in the system 10 at or near the downhole portion of the drillstring 11. A modular downhole tool 20 is disposed in the BHA 18 or other location in the drillstring 11, and includes a blowout preventer (BOP) 25 capable of sealing off a portion of the borehole 12 upon detection of an influx of fluid or loss of drilling mud circulation. In one embodiment, the BHA 18 includes a drill bit 22 to drill through earth formations. The drill bit 22 is powered by a surface rotary drive, a motor using pressurized fluid (e.g., mud motor, not shown) an electrically driven motor and/or other suitable mechanism.

As described herein, “borehole” or “wellbore” refers to a single hole that makes up all or part of a drilled well. As described herein, “formations” refer to the various features and materials that may be encountered in a subsurface environment. Accordingly, it should be considered that while the term “formation” generally refers to geologic formations of interest, that the term “formations,” as used herein, may, in some instances, include any geologic points or volumes of interest (such as a survey area). In addition, it should be noted that the drillstring may be any structure suitable for lowering a tool through a borehole or connecting a drill to the surface, and is not limited to the structure and configuration described herein. The drillstring 11 may be configured as a drillstring, production string or other borehole string. As used herein, a “string” refers to any structure, tool or apparatus configured to be lowered within a borehole in an earth formation.

Referring to FIG. 2, in one embodiment, the tool 20 includes a modular downhole blowout preventer (BOP) assembly that is configured to control influx into and/or loss of fluid from the borehole 12. The BOP assembly is included to seal off the borehole 12 in the event of an influx of gas and/or fluid or a loss of circulation. As described herein, “blowout” refers to uncontrolled fluid or gas flow from an earth formation into a wellbore which could potentially flow to the surface, and/or any fluid or gas flow from the formation and/or the borehole into the surface environment.

The tool 20 includes at least one of a plurality of modular units serving various functions. In one embodiment, the tool 20 includes a plurality of modular units. Each unit is also referred to herein as a “sub”, which is an interchangeable component of the tool 20 and is connectable to other subs to form selected drillstring sections and/or sections of the BHA 18. Examples of subs include but are not limited to an upper crossover sub 28 such as a wired pipe or other adapter sub, a power/pulser sub 30, a battery sub 31, a communication sub 32 to receive and send commands, a packer sub 34, a bypass sub 36 (in one embodiment, the bypass sub 36 is located above the packer sub 34 to allow circulation, as shown in FIG. 2), a string valve sub 37, a sensor sub 38 (e.g., for kick detection), a decoder sub 40, and a lower crossover sub 42 connected to the string or the BHA 18. In one embodiment, the sensor sub 38 includes one or more sensors for detecting a kick. In one embodiment, the subs are integrated into the BHA 18 and are configured to communicate with the surface via suitable LWD equipment. The individual placement of the subs within the tool 20 is exemplary, as the subs may be placed relative to one another in any suitable configuration.

Each sub includes a connection mechanism 41, 43 configured to allow each sub to be removed and/or replaced without disassembly of the tool 20. In one embodiment, the connection mechanisms 41, 43 have a common configuration so that each connection mechanism 41, 43 of a respective sub is engageable with the connection mechanism 41, 43 of any other sub.

Each sub can be replaced with a sub having operating characteristics more suited to the particular conditions encountered. For example, the sensor sub 38 can be switched with another sensor sub 38 having a different combination of sensors. In one embodiment, each sub is individually designed to have selected characteristics. For example, the weights and dimensions of each sub is individually determined based on their individual requirements. Housings for each sub include any selected materials or combinations to have selected resistances to the borehole environment, such as pressure, temperature and corrosion.

In one embodiment, the upper crossover sub 28 and the lower crossover sub 42 include electrical conduits 44 for coupling power and/or communication signals from an electric cable or other wire in the drillstring 11 and/or BHA 18 to the modular assembly, i.e., the tool 20. The upper crossover sub 28 may also be configured to couple other power/communication setups to the modular assembly 20, such as wireline connections and logging-while-drilling (LWD) connections. In one embodiment, the upper crossover sub 28 is configured to be connected to a drillstring, wired pipe or wireline.

In one embodiment, the power/pulser sub 30 includes a power source 46 such as at least one battery and a suitable electronics unit 48 to regulate voltage, current and/or frequency of power supplied to the modular assembly 20. In one embodiment, the power/pulser sub 30 is capable of running the tool 20 at low or even no flow. Exemplary batteries include rechargeable batteries, lithium batteries and nickel cadmium (Ni—Cd) batteries. In one embodiment, the power source 46 is included that individually powers each module. For example, the power source 46 includes one or more batteries 46 to operate the sensor sub 38 and one or more batteries 46 to operate the packer sub 34. Various subs are powered by the power source 46, the wired pipe adapter 28 or any other suitable power source.

In one embodiment, the sensor sub 38 includes at least one sensor 50 configured to measure various properties of the borehole 12 and/or the formation 14, such as a pressure sensor. Examples of such properties include pressure, flow rate, gas content, mud composition and others. In one embodiment, the pressure sensor 50 is an electrically conductive member that changes resistance due to changes in strain in response to pressure variations. In one embodiment, a sensor electronics unit 52 is coupled to the sensor 50 and measures a current change to calculate change in resistance and the corresponding pressure change. The sensor electronics unit 52 may include its own power source or measure current applied by the power/pulser sub 30. In one embodiment, the sensor electronics unit 52 includes an amplifier to amplify the signal generated therein. The sensor sub 38, in addition to pressure sensors, may include any number or type of additional sensors to detect various conditions in and/or characteristics of the borehole, the circulating fluid and/or the formation.

The decoder sub 40, in one embodiment, includes a decoder electronics unit 54, such as a microprocessor, to receive input from the sensor sub 34 and actuate the packer sub 34 when a sufficient change in a property is detected. The decoder electronics unit 54 is configured to recognize when a change in a property occurs beyond a selected threshold, and in response actuate the packer sub 34 to seal off a portion of the borehole 12. In one embodiment, the decoder electronics unit 54 is configured to be in a sleeping mode when the tool 20 is out of hole, and to power up when the tool 20 is exposed to pressure to preserve power and protect the tool 20 from premature actuation during transport and storage.

Referring to FIG. 3, the bypass sub 36 includes a bypass assembly having a valve 56 and bypass electronics unit 58 for controlling the valve 56 to allow mud to flow from the interior of the drillstring 11 to an exterior of the drillstring 11 and into the borehole 12. In one embodiment, the valve 56 is a poppet valve cooperating with a bypass annulus 60 or other conduit to engage in fluid communication with an interior conduit 62 of the drillstring 11. In the closed position shown in FIG. 3, the poppet valve seals 56 off the annulus 60 to prevent fluid flow between the interior conduit 62 and an exterior of the drillstring 11. In the open position, the poppet valve 56 is moved to allow fluid flow through the annulus. In one embodiment, the bypass electronics unit 58 includes various sensors and/or motors for sensing a condition in which bypass is needed and/or to actuate the valve 56. In one embodiment, the bypass sub includes a string valve 57, which may be connected to suitable control electronics 59, for controlling fluid flow through the drillstring 11. The string valve may be a poppet valve or any other suitable valve configuration. In one embodiment, the bypass assembly and the drillstring valve 57 are housed in separate modules that can be individually removed and attached to the tool 20. In one embodiment, the string valve 57 is located below the valve 56 to allow bypass circulation in the event that the string valve 57 is actuated to close the string.

Referring to FIGS. 4 and 5, the packer sub 34 includes a string valve 63, a packer element 64 and an actuator assembly 66 including a packer valve 67 such as a poppet valve. Although the string valve 63 and the valve 67 are shown as poppet valves, either may take any suitable configuration. The actuator assembly 66 includes electronics and/or pressure sensors for controlling actuation of the valve 67 and/or the element 64. The actuator assembly 66, in one embodiment, is disposed in communication with the decoder sub 40, for example, which in turn activates the actuator assembly 66 to cause the packer 64 to inflate or otherwise extend radially toward the sides of the borehole 12 to seal off a section of the borehole 12. FIG. 4 shows the actuator assembly 66 in a non-actuated or drilling position, and FIG. 5 shows the actuator in an actuated position. When the packer sub 34 is in the actuated mode, both the drillstring 11 and a fluid conduit 68 within the packer sub 38 housing is sealed off. The drilling fluid or mud 16 is now circulated through a circulation port 70 just above the annular seal formed by the poppet valve 67 and directed to an annulus 72 through one or more bores 74 to inflate the packer element 64. In one embodiment, the valve 63 is located below the valve 67 to allow for bypass circulation, and may also be located below the packer element 64.

In one embodiment, the system includes four independently operating valves. For example, the valves are incorporated into the bypass sub 36 and/or the packer sub 34 and are configured with the bypass valve 56 located above the packer valve 67. In one embodiment, the packer valve 67 is configured as independently operating inflation and deflation valves. The string valve 63, which may be located in the separate string valve sub 37 and/or the bypass sub 36, is located below the bypass valve 56 and the packer valve(s) 67. Such a configuration allows for increased flexibility to perform various functions such as measuring the bottom hole pressure development inside the drill pipe, i.e., the shut-in drill pipe pressure (SIDPP), releasing a kick through the drill pipe instead of the annulus, and bullheading the formation. This configuration is also useful in performing drill stem testing.

In one embodiment, the actuator assembly 66 includes one or more of an electric motor, a translational mechanism such as a roller screw, the valve 67, and the circulation port 70. In one embodiment, the electric motor is started by the decoder sub 40 when the detected pressure change is beyond a selected threshold. In one embodiment, motor current is continuously controlled by the decoder electronics 54 during actuation. The motor current increases at the end position of the poppet stroke, and is switched off by the decoder electronics 54 at a predetermined value. In one embodiment, if any unforeseen motor loads should occur during actuation, the decoder electronics 54 are configured to control the current to prevent damage to the packer sub 34.

The circulation port 70 extends from an exterior of the packer sub 34 to the interior conduit 68 through which mud or other fluid or gas is introduced. In the actuated mode, the poppet valve 67 seals the drillstring 11 and opens the circulation port 70 to allow fluid to enter the annulus 72 and inflate the packer element 64. In one embodiment, the packer is automatically deflated by internal stresses in the packer element when the circulation port 70 is closed and the tool 20 is in the drilling mode.

In one embodiment, one or more of the components of the actuator assembly 66, such as the electronics unit, motor, roller screw and the poppet valve 67 each form their own modular sub-assembly. In another embodiment, the actuator assembly 66 and the packer element 64 are each disposed within their own modular sub.

Although the embodiment shown in FIG. 2 includes subs 28, 30, 32, 34, 36, 38, 40 and 42, the tool 20 is not limited to the exemplary number and types of subs or modules described herein. Any number or type of modules may be included to provide selected functionality for blowout prevention and other uses. In one embodiment, the tool 20 includes all of the subs 28, 30, 32, 34, 36, 38, 40 and 42 described herein in the order shown. However, any number of subs may be added or omitted, or the order of the subs changed. Tool modifications may also introduce additional functions such as multi-operational circulation ports, drillstring chokes and test plugs for traditional BOPs.

Each modular unit is interchangeable and includes the standardized connection interface 41, 43 to allow for each sub to be interchangeable with any other sub. In one embodiment, the connection interface 41, 43 is standardized among all of the subs to allow for each sub to be interchangeable with any other sub. Such interchangeability allows for the BHA 18 and/or tool 20 to be easily adjusted to account for different operation needs. In one embodiment, all electric wires for communication to other modules are located in the center of each module for simple connection and disconnection. In one embodiment, one or more of the subs are encased in a protective housing, for example a resilient or rubberized casing to protect the sub from shocks and vibrations.

Examples of connections 41, 43 include shaft connections, threaded connections, bayonet and pin connections. In one embodiment, shown in FIG. 2, each sub has a male connection 41 and a female connection 43, which may be tapered or straight. In one embodiment, each connection 41, 43 includes an electrical and/or signal connection to couple power and communication signals between subs.

Referring again to FIG. 2, sensors 50, in other embodiments, include sensors that are used to measure properties of the formation 14, to measure properties of the borehole 12 and/or to assess the stresses on and operation of the tool 20. Examples of such sensors 50 include pressure sensors, current sensors, vibration sensors, temperature sensors flow rate sensors, gas content and/or mud composition sensors and others.

Referring again to FIG. 1, in one embodiment, the tool 20 is equipped with transmission equipment to communicate ultimately to a surface processing unit 26. Such transmission equipment allows the tool 20 to send critical data to the surface, stop or otherwise control pipe rotation, stop or otherwise control axial movement, control fluid flow, receive and decode commands sent downhole to activate the tool, and perform other functions. Such transmission equipment may take any desired form, and different transmission media and connections may be used. Examples of connections include wired pipe, fiber optic, wireless connections, mud pulse telemetry and any other suitable communication utilized in logging-while-drilling (LWD) equipment.

In one embodiment, the surface processing unit 26 and/or the tool 20 include components as necessary to provide for storing and/or processing data collected from the tool 20. Exemplary components include, without limitation, at least one processor, storage, memory, input devices, output devices and the like. The surface processing unit 26 optionally is configured to control the tool 20.

FIGS. 6-8 illustrate various examples of the tool 20. Referring to FIG. 6, in a first example, the tool 20 includes a wired pipe adapter sub 76 in a modular connection with a BOP sub 78, that includes a battery sub. Referring to FIG. 7, in a second example, the tool 20 includes a bi-directional power and communications module 80 in a modular connection with the BOP sub 78. Referring to FIG. 8, in a third example, the tool 20 includes a low flow pulser/decoder sub 82 in a modular connection with the BOP sub 78.

Referring to FIG. 9, there is provided a system 80 for preventing blowouts, or other device used in conjunction with the BHA 18 and/or the drillstring 11. The system 80 may be incorporated in a computer or other processing unit capable of receiving data from the tool 20. The processing unit may be included with the tool 20 or included as part of the surface processing unit 26.

In one embodiment, the system 80 includes a computer 81 coupled to the tool 20. Exemplary components include, without limitation, at least one processor, storage, memory, input devices, output devices and the like. As these components are known to those skilled in the art, these are not depicted in any detail herein. The computer 81 may be disposed in at least one of the surface processing unit 24 and the tool 20.

Generally, some of the teachings herein are reduced to an algorithm that is stored on machine-readable media. The algorithm is implemented by the computer 81 and provides operators with desired output.

FIG. 10 illustrates a method for preventing blowouts in a borehole. The method includes one or more of stages 101-104 described herein. The method may be performed continuously or intermittently as desired. The method is described herein in conjunction with the tool 20 and optionally the decoder sub 40, although the method may be performed in conjunction with any number and configuration of processors, sensors and tools. The method may be performed by one or more processors or other devices capable of receiving and processing measurement data, such as the microprocessor and/or the computer 81. In one embodiment, the method includes the execution of all of stages 101-104 in the order described. However, certain stages 101-104 may be omitted, stages may be added, or the order of the stages changed.

In the first stage 101, subs are selected and the modular assembly 20 is assembled by connecting each sub in operable communication via the connections 41, 43. In one embodiment, the selection of subs and the position within the assembly depend on the assessment of the blow out risk and the property chosen to trigger an adequate reaction.

In the second stage 102, a change in a property, such as pressure, that is greater than a selected threshold is detected. Information regarding the property change may be sent to the surface for decision. Such decisions include reacting conventionally without use of the downhole BOP, and/or stopping string movement and activating the downhole BOP, and/or running an automatic process at the surface and/or downhole. Transmitting the information to surface may be done with wired pipe, conventional mud pulse telemetry or other suitable means. In one embodiment, a pressure code is generated in the pulser sub in response to the change in pressure.

In the third stage 103, a code depending on the selected action is transmitted inside the drillstring 11 (via pulse, wired pipe, etc.) to the packer sub 34 and/or the decoder sub 40, and the packer sub 34 is actuated to cause the packer element 64 to seal off a portion of the borehole 12. When the packer sub 34 is actuated, both the drillstring 11 and the borehole 12 are sealed off. Actuation moves the poppet valves 63 and 67, e.g., after the electronic unit in the actuator assembly 66 has accepted the code. The drillstring 11 is closed and the circulation port 70 is opened to seal off the lower part of the borehole 12.

In the fourth stage 104, the section of the borehole 12 above the packer sub 34 is circulated with mud 16 of sufficient density to equalize pressure in the borehole 12 to regain control of the borehole pressure and stabilize the borehole 12. After the borehole 12 is stabilized, the packer sub 34 is reset back to normal drilling mode, e.g., by sending a new pressure code.

The systems and methods described herein provide various advantages over prior art techniques. The embodiments described herein offer greatly increased system flexibility, which allows the tool to be easily adjusting to coincide with changing operational needs. Examples of such embodiments are described above.

In support of the teachings herein, various analyses and/or analytical components may be used, including digital and/or analog systems. The system may have components such as a processor, storage media, memory, input, output, communications link (wired, wireless, pulsed mud, optical or other), user interfaces, software programs, signal processors (digital or analog) and other such components (such as resistors, capacitors, inductors and others) to provide for operation and analyses of the apparatus and methods disclosed herein in any of several manners well-appreciated in the art. It is considered that these teachings may be, but need not be, implemented in conjunction with a set of computer executable instructions stored on a computer readable medium, including memory (ROMs, RAMs), optical (CD-ROMs), or magnetic (disks, hard drives), or any other type that when executed causes a computer to implement the method of the present invention. These instructions may provide for equipment operation, control, data collection and analysis and other functions deemed relevant by a system designer, owner, user or other such personnel, in addition to the functions described in this disclosure.

Further, various other components may be included and called upon for providing aspects of the teachings herein. For example, a sample line, sample storage, sample chamber, sample exhaust, pump, piston, power supply (e.g., at least one of a generator, a remote supply and a battery), vacuum supply, pressure supply, refrigeration (i.e., cooling) unit or supply, heating component, motive force (such as a translational force, propulsional force or a rotational force), magnet, electromagnet, sensor, electrode, transmitter, receiver, transceiver, controller, optical unit, electrical unit or electromechanical unit may be included in support of the various aspects discussed herein or in support of other functions beyond this disclosure.

One skilled in the art will recognize that the various components or technologies may provide certain necessary or beneficial functionality or features. Accordingly, these functions and features as may be needed in support of the appended claims and variations thereof, are recognized as being inherently included as a part of the teachings herein and a part of the invention disclosed.

While the invention has been described with reference to exemplary embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications will be appreciated by those skilled in the art to adapt a particular instrument, situation or material to the teachings of the invention without departing from the essential scope thereof Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the appended claims. 

1. A system for monitoring and controlling fluid flow through a borehole in an earth formation, the system comprising: a downhole tool configured to be movable within the borehole; and a plurality of interchangeable modules disposed within the downhole tool, the plurality of interchangeable modules including at least a sensor module for detecting a property change in the borehole and a packer module for sealing a portion of the borehole in response to the property change, each of the plurality of interchangeable modules including a connection configuration, the connection configuration of one of the modules being removably engageable with at least another of the modules.
 2. The system of claim 1, wherein the downhole tool includes a segmented tool body having a plurality of segments, each segment having compatible connection mechanisms to allow each of the plurality of interchangeable modules to be replaced.
 3. The system of claim 1, wherein the connection includes a common connection configuration, the connection configuration of one of the modules being engageable with any other of the modules.
 4. The system of claim 1, wherein the property change is detection of an influx of fluid or loss of fluid circulation.
 5. The system of claim 1, wherein the sensor module includes at least one additional sensor for measuring selected characteristics of at least one of the borehole and the formation
 6. The system of claim 5, wherein the property change is selected from a change in at least one of a pressure, flow rate, gas content and fluid composition.
 7. The system of claim 1, further comprising at least one additional module selected from at least one of an upper crossover module, a power/pulser module, a communication module, a bypass module, a decoder module and a lower crossover module.
 8. The system of claim 1, wherein the connection configurations are selected from one of a shaft connection, a threaded connection, a bayonet connection and a pin connection.
 9. The system of claim 1, wherein the packer module includes an actuator and a packer, the actuator configured to cause the packer to extend radially toward a surface of the borehole.
 10. The system of claim 9, wherein the actuator includes at least one valve, and the packer is an inflatable member surrounding an annulus, the valve being actuateable to open a circulation port and cause drilling fluid to enter the annulus and inflate the packer.
 11. A method of monitoring and controlling fluid flow through a borehole in an earth formation, the method comprising: disposing a plurality of interchangeable modules within a downhole tool, the plurality of interchangeable modules including at least a sensor module and a packer module, each of the plurality of interchangeable modules including a connection configuration, the connection configuration of one of the modules being removably engageable with at least another of the modules. detecting a change in property in the borehole by the sensor module; and responsive to the change in property being greater than a selected threshold, actuating the packer sub to seal a portion of the borehole.
 12. The method of claim 11, wherein detecting the change in property includes detecting an influx of fluid or loss of fluid circulation.
 13. The method of claim 11, further comprising measuring at least one additional selected characteristic of at least one of the borehole and the formation.
 14. The method of claim 11, wherein detecting the change in property includes detecting a change in at least one of a pressure, flow rate, gas content and fluid composition.
 15. The method of claim 11, wherein disposing the plurality of interchangeable modules includes connecting each of the plurality of modules together via the common connection configuration.
 16. The method of claim 11, wherein the packer module includes an actuator and a packer, and actuating the packer module includes causing the packer to extend radially toward a surface of the borehole.
 17. The method of claim 16, wherein the actuator includes at least one valve, the packer is an inflatable member surrounding an annulus, and actuating the packer module includes opening a circulation port and causing drilling fluid to enter the annulus and inflate the packer.
 18. The method of claim 11, further comprising circulating a fluid having a selected density in a section of the borehole to equalize pressure in the borehole.
 19. The method of claim 11, wherein the plurality of interchangeable modules includes at least one additional module selected from at least one of an adapter sub, a power/pulser sub, a bypass sub, and a decoder sub.
 20. The method of claim 11, wherein the connection configurations are selected from one of a shaft connection, a threaded connection, a bayonet and a pin connection. 